Currently, it is the usual practice to burn refinery and petrochemical off-gas streams containing ethylene in flare stacks or as fuel even though the fuel gas value of the streams is significantly less than the product value of the recoverable ethylene. The high cost of producing ethylene by thermal cracking of hydrocarbon feedstocks, which is the primary production route to ethylene, should motivate ethylene consumers to recover ethylene from off-gas streams that are emitted in their complexes before opting to build or expand thermal cracking units or to purchase makeup ethylene. Recovery of ethylene from refinery off-gas streams is particularly feasible at the many sites where the off-gas streams are near an ethylene plant because the recovered ethylene stream can conveniently be purified in towers already operating in the ethylene plant.
The principal ethylene bearing off-gas streams are from fluid catalytic cracking (FCC) units and delayed cokers. A typical fluid catalytic cracker unit emits between about 20,000 to 30,000 tons per year of ethylene in off-gas streams. In North America, fluid catalytic cracker units alone produce about 6,000 MM lbs/Yr of ethylene and about 500 MMSCFD of hydrogen which are potentially recoverable.
Demand in refining and petrochemical operations for hydrogen to desulfurize feedstocks and liquid heavy fractions is increasing because sulfur in crude solvents now being refined is increasing and more heavy crudes with higher carbon-to-hydrogen ratio are being produced. It is estimated that petroleum refineries and petrochemical plants in North America are burning off-gases containing 1,500 to 2,000 million cubic feet per day of recoverable hydrogen. Paradoxically, the hydrogen in these streams is not recovered; the streams are burned in flare stacks, vented to the atmosphere or burned as fuel in fuel gas. Most of the chemical hydrogen used in refineries and chemical plants is made on purpose at substantial cost by steam reforming or partially oxidizing methane and other hydrocarbons followed by purification in pressure swing adsorption units and membrane diffusion units.
Table 1 presents a range of compositions of typical ethylene bearing off-gas streams.
TABLE 1 ______________________________________ Component Volume % ______________________________________ H.sub.2 7-48 N.sub.2 0-12 CH.sub.4 15-58 C.sub.2 H.sub.4 2-15 C.sub.2 H.sub.6 2-25 C.sub.3+ 2-15 ______________________________________
Ethylene bearing off-gases usually contain methane and often also hydrogen in economically recoverable quantities. Ethylene bearing refinery and petrochemical off-gas streams also contain varying amounts of heavy hydrocarbons in the C4 to C10 range which can include alkanes, olefins and aromatics. Small amounts of water, nitrogen oxides, carbon monoxide, carbon dioxide, acetylene, methylacetylene, propadiene, butenes, and higher hydrocarbons are typically also found in ethylene bearing off-gases.
Why don't operators recover ethylene and associated hydrogen from off-gas streams? The answer is that it costs more to recover ethylene and hydrogen using the cryogenic recovery technology and processes than to purchase or produce the makeup ethylene. Even adding in the chemical value of associated hydrogen, which is two to three times its fuel value, does not make recovering ethylene from off-gas streams using cryogenic technology cost effective. Moreover, cryogenic processes are not flexible and do not adapt well to changes in feed composition and feed gas flow rates that are endemic to refinery and petrochemical off-gas streams, so that while cryogenic recovery is technically feasible, it is impractical in most applications. Another consideration is that several devastating explosions in cryogenic ethylene recovery units have been attributed to formation of explosive compounds from nitrogen oxide, which are found in most off-gas streams, at the very low temperatures encountered in cryogenic units.
For the foregoing reasons, there is need for a cost effective, flexible and safe process for recovering ethylene and associated hydrogen from refinery and petrochemical off-gas stream.
The solution lies in Mehra processes which are absorption processes that utilize a physical absorption solvent to separate and recover hydrogen, methane, ethylene and other valuable hydrocarbons from mixed hydrocarbon streams. Mehra technology has been applied to recover ethylene, hydrogen and methane from refinery and petrochemical off-gas streams and to reject nitrogen from natural gas. Generally, Mehra processes compete with cryogenic processes in these applications. Depending on the application, Mehra specifies absorption solvents that are selected from preferred groups and processed designs which optimally synergize solvent with process. Among the preferred Mehra solvents are C4 to C10 hydrocarbons, including paraffins, naphthenes and aromatics. Mehra technology is described in U.S. Pat. Nos. 4,832,718, 4,740,222, 5,019,143, 5,220,097 and 5,326,929, which are incorporated herein by reference.
In general, Mehra processes operate at a higher temperature than cryogenic processes which provide advantages over cryogenic processes: 1) exotic cryogenic construction materials required to withstand cryogenic temperatures are not required in Mehra processes; 2) feed purification specifications are more relaxed; 3) cryogenic processes are intensively heat integrated to reduce energy consumption whereas Mehra processes are not. Accordingly, Mehra processes are more flexible and adaptable to changes. Process conditions can be changed quickly "on-line" with no adverse impact on operability and without equipment modifications to alter product stream compositions or maintain product composition should feed composition change.
While the Mehra technology has provided many advances over the cryogenic processes, there continually exists a need to refine the processes to attain more efficient and cost effective measures.